ML13329A147
| ML13329A147 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 04/11/1990 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13329A148 | List: |
| References | |
| 50-206-90-02, 50-206-90-2, 50-361-90-02, 50-361-90-2, 50-362-90-02, 50-362-90-2, NUDOCS 9005240294 | |
| Download: ML13329A147 (45) | |
See also: IR 05000206/1990002
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION V
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SALP BOARD REPORT
Nos. 50-206/90-02, 361/90-02, 362/90-02
SOUTHERN CALIFORNIA EDISON COMPANY
SAN ONOFRE NUCLEAR GENERATING STATION
OCTOBER 1, 1988 THROUGH JANUARY 31, 1990
9 00
C24294
- C
900411
ADOCK 05:00206.
PDLEc:
TABLE OF CONTENTS
Page
I.
Introduction.
.
..............
.
. . . . ..
1
II. Summary of Results.
............. ....
. . . .
2
A.
Effectiveness of Licensee Management.........
.
2
B.
Results of Board Assessment.
............. .
3
C.
Changes in SALP Ratings. ........... .
. . . .
3
III. Criteria.
.
... ..............
..
. . . .
4
IV.
Performance Analysis.
............ .....
. . .
5
A.
Plant Operations. . . . ................ 5
B. Radiological Controls . ................
8
C. Maintenance/Surveillance................
10
D. Emergency Preparedness. . . . . . . . . ........ 13
E. Security.
.
..............
15
F. Engineering/Technical Support . . .
. . ........ 17
G.
Safety Assessment/Quality Verification. ........
20
.
V.
Supporting Data and Summaries. . . ............. 23
A.
Licensee Activities . . . . .
.23
B. Direct Inspection and Review Activities ........
25
C.
Enforcement Activity.................
25
D. Confirmation of Action Letters . . . . ........ 25
E. Orders..........
25
F. AEOD Assessment of Licensee Event Reports .. .. ....
26
TABLES
Table 1 -
Inspection Activities and Enforcement Summary
Table 2 -
Enforcement Items
Table 3 -
Synopsis of Licensee Event Reports
ATTACHMENT
AEOD Analysis of Licensee Event Reports
U. S. NUCLEAR REGULATORY COMMISSION
REGION V
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SALP BOARD REPORT
Nos. 50-206/90-02, 361/90-02, 362/90-02
SOUTHERN CALIFORNIA EDISON COMPANY
SAN ONOFRE NUCLEAR GENERATING STATION
OCTOBER 1, 1988 THROUGH JANUARY 31, 1990
TABLE OF CONTENTS
Page
I. Introduction.
.
...............
...
. .
1
II. Summary of Results........... ......
. . . . .
2
A.
Effectiveness of Licensee Management.....
. . . . .
2
B.
Results of Board Assessment......... ..
. . . .
3
C.
Changes in SALP Ratings........... .
. . . . .
3
III. Criteria.......
..............
.
. .
4
IV.
Performance Analysis..........
......
. . . . .
5
A.
Plant Operations..5
B.
Radiological Controls. .. ....... .........
8
C. Maintenance/Surveillance. .. ... ........ ...
10
D.
Emergency Preparedness. .. ... ........ ....
13
E. Security.....15
F.
Engineering/Technical Support. .. ...... ...... 17
.
Safety Assessment/Quality Verification....
. . . . ..
20
V. Supporting Data and Summaries . . ...............
23
A.
Licensee Activitiess. . . . . .
. . . . ..... ...
23
B.
Direct Inspection and Review Activities .. ... ....
25
C.
Enforcement Activity . .
. .
. . . . . . . ... ...
25
D.
Confirmation of Action Letters .. ....... ....
25
E. Orders.
25
F. AEOD Assessment of Licensee Event Reports.... ..
.
26
TABLES
Table 1 -
Inspection Activities and Enforcement Summary
Table 2 -
Enforcement Items
Table 3 -
Synopsis of Licensee Event Reports
ATTACHMENT
AEOD Analysis of Licensee Event Reports
.1.
INTRODUCTION
The Systematic Assessment of Licensee Performance (SALP) is an NRC staff
integrated effort to collect available observations and data on a
periodic basis and to evaluate licensee performance based on this
information. The program is supplemental to normal regulatory processes
used to ensure compliance with NRC rules and regulations. It is intended
to be sufficiently diagnostic to provide a rational basis for allocating
NRC resources and to provide meaningful feedback to the licensee's
management regarding the NRC's assessment of their facility's performance
in each functional area.
An NRC SALP Board, composed of the members listed below, met in the
Region V office on March 15, 1990, to review observations and data on the
licensee's performance in accordance with NRC Manual Chapter 0516,
"Systematic Assessment of Licensee Performance," dated August 16, 1989.
The Board's findings and recommendations were forwarded to the NRC
Regional Administrator for approval and issuance.
This report is the NRC's assessment of the licensee's safety performance
at San Onofre for the period October 1, 1988 through January 31, 1990.
The SALP Board for San Onofre was composed of:
- R. P. Zimmerman, Director, Division of Reactor Safety and Projects,
(Board Chairman)
- A. E. Chaffee, Deputy Director, Division of Reactor Safety and
Projects
E. W. Merschoff, Deputy Director, Division of Reactor Safety,
Region II
- C. M. Trammell, Acting Director, Project Directorate V, NRR
- S. A. Richards, Chief, Reactor Projects Branch
- G. P. Yuhas, Chief, Emergency Preparedness and Radiological
Protection Branch
- P H. Johnson, Chief, Reactor Projects Section 3
F. A. Wenslawski, Chief, Facilities Radiological Protection
Section
- F. R. Huey, Chief, Engineering Section
M. D. Schuster, Chief, Safeguards Section
- J. E. Tatum, Unit 1 NRR Project Manager
- L. E. Kokajko, Units 2 and 3 NRR Project Manager
- C. W. Caldwell, Senior Resident Inspector
K. Prendergast, Emergency Preparedness Analyst
A. McQueen, Safeguards Inspector
- Denotes voting member (in all functional areas).
Other persons
advised the Board in areas of cognizance.
- S
2
OI.
SUMMARY OF RESULTS
A. Effectiveness of Licensee Management
Notable licensee achievements were observed during this SALP period.
Overall plant performance was good, with few transients and no
significant complications. The number of reactor trips and other
significant events was slightly higher than during the previous
period, but still relatively low. Weaknesses were noted in the
Plant Operations area involving insufficient attention to detail and
inadequate training in normal operations, resulting in several
operational errors during the assessment period. Other weaknesses
were observed in association with non-conservative application or
interpretation of Technical Specification (TS) requirements, and the
staffing level of licensed operators was impacted by a higher than
normal attrition rate.
In the Maintenance/Surveillance functional area, the Board
considered the licensee to have defined a very effective Maintenance
and Surveillance program, although minor weaknesses in program
implementation were observed during the performance of maintenance
activities. The licensee has also shown initiative in the
Maintenance area by the use of innovative analysis techniques (e.g.,
Electronic Characterization and Diagnostics (ECAD) System). In
addition, the licensee has demonstrated an aggressive Radiological
Controls program which has served as an industry leader in several
respects. Effective management controls, ample and capable
staffing,. and self-critical attitudes also provided good overall
performance in the Emergency Preparedness and Security areas.
Strengths were also observed in other functional areas. In
particular, the licensee was aggressive in upgrading programs to
enhance the effectiveness of Engineering/Technical Support and
Safety Assessment/Quality Verification activities. These efforts
reflected strong management support of initiatives in these
functional areas.
Results were being achieved, as exemplified by
significant design problems identified by Engineering and by
meaningful audit/surveillance findings by the Quality Oversight
organizations. However, weaknesses were also observed in these
areas. In the Engineering/Technical Support area, problems were
observed with regard to inadequate translation of the design bases
to component setpoints, and in the lack of formal calculations for
key design parameters related to some of the electrical distribution
systems. In addition, there were a few examples of problems with
design changes that manifested themselves in plant events. With
regard to the Safety Assessment/Quality Verification area,
weaknesses were observed in the adequacy of the corrective action
program, safety evaluations, and licensing submittals.
The weaknesses noted above were discussed during periodic meetings
with licensee management. These discussions emphasized a need for a
continued self-critical attitude by SCE in addressing areas of
weakness, particularly involving attention to detail during the
3
performance of work activities. In a manner indicative of such a
self-critical attitude, senior SCE management recognized the
significance of weaknesses observed during the last SALP period and
initiated comprehensive actions to improve performance in the
Engineering/Technical Support and Safety Assessment/Quality
Verification functional areas. These efforts included a corporate
reorganization to put all such activities under one Vice President,
a move of the Engineering department closer to the San Onofre
Station, relocation of all quality oversight organizations to the
site, and initiation of a comprehensive review and updating of the
plant's design basis documents.
B. Results of Board Assessment
Overall, the SALP Board found the performance of NRC licensed
activities by the licensee to be acceptable and directed toward safe
operation of the San Onofre Station. The SALP Board has made
specific recommendations in most functional areas for licensee
management consideration. The results of the Board's assessment of
the licensee's performance in each functional area, along with the
previous assessments, are as follows:
Rating
Rating
Last
This
Functional Area
Period
Period
Trend*
A. Plant Operations
1
2
B. Radiological Controls
1
1
C. Maintenance/
2
1
Surveillance
1
1
E. Security
1
1
F. Engineering/Technical
3
2
Support
G. Safety Assessment/
3
2
Quality Verification
The SALP report may include an appraisal of the performance
trend in a functional area for use as a predictive indicator.
Licensee performance during the assessment period should be
examined to determine whether a trend exists. Normally, a
performance trend will be indicated only if (1) a definite
trend is discernible and (2) continuation of the trend could
result in a change in performance rating. The performance
trend is intended to predict licensee performance during the
next assessment period and should be helpful in allocating NRC
resources.
C. Changes in SALP Ratings
Changes to the SALP ratings occurred in the Plant Operations,
Maintenance/Surveillance, Engineering/Technical Support, and Safety
Assessment/Quality Verification functional areas. Performance in
4
Plant Operations declined from the previous Category 1, primarily
due to instances of non-conservative application or interpretation
of Technical Specification requirements, and several events
involving operator error. These events appeared to result from
insufficient attention to detail and inadequate training in normal
operations. A decreased licensed operator staffing level on Units 2
and 3 (due to a higher than normal attrition rate) also warrants
management attention because of its potential impact on future plant
performance in the Plant Operations area.
Performance in the Maintenance/Surveillance functional area was
concluded to have improved due to a well-defined program and
significant licensee initiatives in this area, including
improvements in the control and scheduling of work, and the use of
innovative maintenance techniques. Performance in this area was
assessed as Category 1; nevertheless, the SALP Board noted several
examples of problems associated with the implementation of that
program. As a result, the Board recommends that the licensee
continue to promote the concept of attention to detail during the
performance of work, and strengthen supervisory review of work
(including work plans) to assure that maintenance activities are
performed safely and efficiently.
Performance was -found to have improved in the Engineering/Technical
Support and Safety Assessment/Quality Verification functional areas
due to the licensee's aggressiveness in upgrading programs to
enhance the effectiveness of these areas. These involved relocation
of cognizant organizations closer to (or at) the site, additional
staffing, and improved processes for performing and managing related
activities. The Board noted strong management support of
initiatives in these functional areas. The higher ratings reflect
the Board's perception that desired notable improvements have been
made in these areas, as discussed further in Sections IV.F and G,
although a need for additional improvement was observed.
III. CRITERIA
Licensee performance is assessed in functional areas described in NRC
Manual Chapter 0516. Appendix A to this manual chapter describes a
number of attributes for each evaluation criterion and provides guidance
on using these criteria to assign a performance rating. The evaluation
criteria were as follows:
1. Assurance of quality, including management involvement and control.
2. Approach to the identification and resolution of technical issues
from a safety standpoint.
3. Responsiveness to NRC initiatives.
4. Enforcement history.
5
5. Operational events (including response to, analysis of, reporting
of, and corrective actions for events).
6. Staffing (including management).
7. Effectiveness of the training and qualifications program.
On the basis of the NRC assessment, each functional area evaluated was
rated according to three performance categories. The definitions of
these performance categories are as follows:
Category 1:
Licensee management attention and involvement are
readily evident and place emphasis on superior performance of
nuclear safety or safeguards activities, with the resulting
performance substantially exceeding regulatory requirements.
Licensee resources are ample and effectively used so that a high
level of plant and personnel performance is being achieved. Reduced
NRC attention may be appropriate.
Category 2:
Licensee management attention to and involvement in the
performance of nuclear safety or safeguards activities are good.
The licensee has attained a level of performance above that needed
to meet regulatory requirements. Licensee resources are adequate
and are reasonably allocated so that good plant and personnel
performance is being achieved. NRC attention may be maintained at
normal levels.
Category 3:
Licensee management attention to and involvement in the
performance of nuclear safety or safeguards activities are not
sufficient. The licensee's performance does not significantly
exceed that needed to meet minimal regulatory requirements.
Licensee resources appear to be strained or not effectively used.
NRC attention should be increased above normal levels.
IV. PERFORMANCE ANALYSIS
The following is the Board's assessment of the licensee's performance in
each of the functional areas, along with the Board's conclusion for each
area and its recommendations with respect to licensee actions and
management emphasis.
A. Plant Operations
1. Analysis
During the SALP period, approximately 1770 hours0.0205 days <br />0.492 hours <br />0.00293 weeks <br />6.73485e-4 months <br /> of direct
inspection effort were applied in the Plant Operations area.
The licensee's strengths continued to be in well-written
operating procedures, administrative controls, and operations
support. A noteworthy accomplishment was a new site record for
continuous operation set by Unit 3 shortly after the end of the
assessment period. Weaknesses identified were associated with
attention to detail and training in normal operations,
6
involving several personnel errors and instances of improper
application of Technical Specification (TS) requirements. In
addition, the staffing level of licensed operators was impacted
by a high attrition rate.
The licensee responded to these
weaknesses, and corrective action plans were being developed at
the end of the assessment period.
In response to the last SALP recommendations, the licensee took
action to strengthen housekeeping and the interface among
Operations, Maintenance, and Technical groups. Safety policies
were reinforced through formal training and periodic reviews.
Management continued to emphasize strict compliance with
procedures, and took other actions to heighten the safety
sensitivity of the operating staff. Corporate management was
effectively involved in site activities and their presence in
the plant was observed regularly, including during backshift
hours. The licensee lowered the threshold for initiating
operating incident investigations. This resulted in the
assessment of more minor events for lessons learned. A general
absence of recurring problems indicated that corrective actions
for events and violations were effective.
The licensee's responses to NRC identified issues were
technically sound, and implementation was timely and effective.
One example was the development of a program, pursuant to an
NRC Bulletin, to control plant evolutions with reduced reactor
coolant system (RCS) inventory.
The trip reduction program appeared to remain effective,
although the number of trips increased slightly over the
previous period. Most were caused by equipment failures, such
as those associated with Units 1 and 3 (as summarized in
paragraph V.A). The Unit 2 CPC trip during startup, on the
other hand, was attributed to operator error and training
weaknesses. In addition, noise in the Unit 1 nuclear instru
mentation system was identified by Operations, but was not
effectively resolved with Engineering, later resulting in a
reactor trip. In the case of manual trips, the operators took
conservative actions and followed the procedures promptly when
the adverse conditions were identified. The licensee's actions
to analyze these events were aggressive and corrective actions
were effective. In addition, the licensee initiated a
professional operator development program to monitor and
enhance operator performance.
In the licensee's approach to the identification and resolution
of technical issues, there were several examples of
non-conservative interpretation or implementation of TS
requirements. Examples of this included (1) management
misinterpretation of NRC Generic Letter 87-09, inappropriately
allowing Unit 2 to be kept at power by invoking a 24-hour
allowance to complete an overdue surveillance test, (2) not
understanding that Unit 1 hot leg recirculation (HLR) was a
7
TS-required feature and that TS 3.0.3 was applicable when
CV-304 failed, and (3) failure to reduce reactor power by 30%
within an hour after a Unit 2 control element assembly slipped
into the core. On the other hand, the facility staff did
exhibit conservatism by shutting down Unit 1 to implement
necessary modifications to the HLR system and shutting down
Unit 2 when it was necessary to perform leak rate testing on
the fuel transfer canal.
In addition, equipment operability
determinations made by Operations, in collaboration with
Station Technical, were generally thorough and conservative.
Other weaknesses were observed in the Plant Operations area, as
evidenced by occasional significant operating events that were
attributable to causes under the licensee's control.
One such
event was a hydrogen ignition and fire in the radwaste building
that resulted partly from program weaknesses and insufficient
training for the control of combustible gases in plant systems.
A number of personnel errors during routine plant evolutions
were also attributed to insufficient attention to detail or to
weaknesses in training on normal operations. Examples were a
misunderstanding by the operators which led to Unit 2 being
taken critical with all four channels of the core protection
calculators (CPCs) indicated as being inoperable, and a
draindown of approximately 700 gallons from the Unit 2 RCS by
an equipment operator who manipulated the wrong valve during a
reduced inventory condition.
With respect to staffing, responsibilities were well defined.
To support the on-shift operators, the licensee had an
experienced equipment control and procedure writing group that
produced quality operating procedures and work requests in
almost all cases.
However, during this assessment period, the
attrition rate for Unit 2 and 3 licensed operators increased to
about double that of the previous year. While some of these
operators were promoted within the Edison organization, thereby
enhancing the depth of other organizations such as QA, many
left the company. This caused some reduction in the experience
base and increased the demand on the remaining operators. NRC
enforcement action also focused attention on excessive use of
overtime, by both Unit 2 and Unit 3 personnel, during the Unit
2 refueling outage. Toward the end of the period, the licensee
initiated recruitment and training actions to improve licensed
operator staffing levels.
The licensee's training and qualification program was well
defined and implemented with dedicated resources and with
effective means for feedback of industry and internal operating
experiences. In particular, the program was effective in
preparing personnel for NRC license examinations, as evidenced
by near 100% pass rates for initial operating license
candidates. Additionally, the administration of the licensee's
requalification program received a satisfactory rating.
However, while many operators examined exhibited strong
8
performance in handling abnormal operations, their performance
for normal operations at times appeared to be weak, as
evidenced during the requalification exams and by some of the
events previously discussed. The licensee initiated corrective
actions to address this deficiency.
The performance of the licensee's fire protection program
during this period was consistent with NRC requirements,
although resolution of several technical issues from the 1988
fire protection team inspection is still in progress. The
licensee has maintained an effective firefighting capability,
including a very capable onsite fire department, and has
.conducted frequent drills to ensure firefighter proficiency.
Inspection activities during the SALP period identified five
severity level IV violations.
Root cause analyses and
corrective actions for the enforcement issues were timely and
effective.
2. Conclusion
Performance Assessment -- Category 2
3. Board Recommendations
The Board recommends that management ensure continued use of a
conservative interpretation and application of TS requirements.
In addition, the licensee should provide continued management
emphasis on procedure compliance, work control, and attention
to detail.
Continuing emphasis should also be given to
strengthening licensed operator training and performance in
routine plant evolutions, and to augmenting licensed operator
staffing levels.
B. Radiological Controls
1. Analysis
This functional area was reviewed routinely during the
assessment period by both regional and resident inspection
staff. Approximately 530 hours0.00613 days <br />0.147 hours <br />8.763227e-4 weeks <br />2.01665e-4 months <br /> of direct inspection effort
were expended in this area. Strengths identified included
comprehensive management control systems, particularly for
ALARA (as low as reasonably achievable exposure) planning; many
highly qualified staff personnel; an effective chemistry
control program; and a commitment at the highest levels of
management to improvements in quality. Housekeeping was
aggressive, resulting in minimization of contaminated areas.
Observed weaknesses evolved around inspector identified
problems in the respiratory protection program, including
training for dosimetry personnel, health physics department
auditing techniques, and maintenance of respirators. The
licensee aggressively pursued root cause evaluation and
9
correction of programmatic aspects of this issue. One
additional weakness observed was the control of radioactive
material, as indicated by several licensee-identified unplanned
releases of low-level radioactive material and one instance of
radiation dose rates in an unrestricted area above the limit.
No problems were indicative of programmatic weaknesses in
radiological controls.
Management control of planning activities continued to play a
significant role in identifying problems before they became
critical factors during maintenance. Health Physics management
continued to meet frequently with their personnel, and
conducted weekly tours of the plant and of ongoing work.
Management commitment to improvement programs and to resolution
of technical issues was responsible for a significant reduction
in the failure rate for effluent and process monitors,
resulting in increased availability of the monitors and fewer
spurious challenges to engineered safety feature systems.
The licensee's staff continued to be a strength, with a low
turnover rate, resulting in retention of highly qualified
personnel.
With the exception of supervision of the respira
tory protection program, which had been delegated to personnel
with other duties, responsibilities were well defined and
personnel in staff positions demonstrated thorough knowledge of
the technical aspects of their areas.
The licensee's training program remained accredited by the
Institute for Nuclear Power Operations (INPO), with many
instructors certified by the National Registry of Radiation
Protection Technologists (NRRPT), and with a high number
(near 100%) of ANSI qualified health physics technicians. The
licensee has approximately 10 American Board of Health Physics
(ABHP) certified health physicists. Management encouragement
of personnel, through company-wide and departmental incentive
programs for excellence and for ALARA improvement suggestions,
maintained a high level of commitment to excellence by the
plant staff.
Programs for chemistry analysis were very good as demonstrated
by staffing, equipment, and procedures. Effective use and
maintenance of condensate polishing demineralizers resulted in
minimal chemical excursions in secondary systems. Routine
quality control methods and fully independent measurement
standards were effective, as demonstrated by a 98% success rate
for initial analyses of NRC Confirmatory Measurements Program
test standards.
The licensee's commitment to improvements in quality was
exemplified by the correction of findings from internal audits,
which were comprehensive. In the instance of a respiratory
protection program audit which was found not to have been
thorough in scope and depth, the licensee promptly instituted
II
10
changes to the program forconduct of health physics audits to
improve audit techniques. Responses to NRC identified problems
were timely and comprehensive, indicating a self-critical and
conservative approach to correcting those problems.
Two cited violations were identified during this assessment
period, as indicated in Table 2. This was a reduction from the
three violations identified during the last SALP period. One
was an isolated incident involving worker instructions in high
radiation areas, which did not indicate a programmatic
deficiency and was expeditiously corrected. The second was
associated with respiratory protection problems, as mentioned
earlier. However, the licensee's comprehensive commitments to
correcting the root causes of the problem appeared to be
sufficient to prevent recurrence.
The station's collective occupational radiation exposure for
1988 was 781 person-rem. This was up somewhat from the station
goal of 750 person-rem, and the 697 person-rem achieved in
1987. The increase was attributed to extensive outage
maintenance and plant aging. The licensee's solid radioactive
waste disposal during 1988, of 97 cubic meters average per
unit, was down slightly from recent previous years.
2. Conclusion
Performance assessment --Category 1
3. Board Recommendations
The Board recommends that the licensee continue efforts to
assure active participation of all site organizations in a
quality Health Physics program, to improve the quality of
health physics audits, and to maintain periodic retraining for
health physics disciplines such as respiratory protection.
C. Maintenance/Surveillance
1. Analysis
During the SALP period, approximately 1750 hours0.0203 days <br />0.486 hours <br />0.00289 weeks <br />6.65875e-4 months <br /> of direct
inspection effort were applied in the maintenance/surveillance
area. In addition to routine inspections, a special
maintenance team inspection was conducted to provide for an
in-depth assessment of this area. An electrical Safety System
Functional Inspection (SSFI) also reviewed the licensee's
maintenance activities. The licensee's strengths continued to
be in maintenance expertise, effective scheduling of surveil
lance tests, implementation of an effective computerized
scheduling and work control system, and use of innovative
maintenance technology applications. A noteworthy
accomplishment was the well-executed transshipment of spent
fuel from Unit 1 to the Units 2 and 3 fuel pools. The major
11
weakness identified was associated with continued instances of
inattention to detail during the performance of work
activities. The licensee recognized this weakness and
continued to strive for excellence in this area.
In the previous SALP report, the Board recommended that
emphasis on a high standard of performance by maintenance
supervision and other personnel be continued, that better
control over the conduct of maintenance activities be exer
cised, and that special attention be given to evaluation and
documentation of discrepant conditions. In response to these
recommendations, the licensee implemented several initiatives
to perform tasks such as improving the quality of procedures
(e.g., using more precise acceptance criteria) so that they
were easier to use and understand. In addition, training was
provided to promote a "do it right the first time" attitude, a
self-assessment task group was formed within the Maintenance
Division to continuously evaluate the quality of activities,
and a review was conducted of discrepant conditions found by
Division Incident Investigations and the nonconformance report
(NCR) process. This appeared to result in the development of
additional rigor in the maintenance process.
With regard to efforts to resolve technical issues, the
licensee has been innovative in many cases by applying state
of-the-art technology and programs for maintenance. For
example, SCE was one of the first utilities to use the
Electronic Characterization and Diagnostics (ECAD) System.
This was successfully used to locate an intermittent instrument
cable ground fault that caused a reactor trip in Unit 1. This
fault would have been almost impossible to locate without ECAD
and could have caused another reactor trip later. The ECAD
system was also used in the preventive maintenance program for
the monitoring of electrical cables. The licensee also
supported NRC initiatives by dedicating resources to assist the
NRC's Office For Analysis And Evaluation Of Operational Data
(AEOD) in development of maintenance performance indicators.
The licensee maintained a very effective surveillance
scheduling program during this period, with only three missed
surveillance tests for the three units.
A maintenance team inspection was conducted in July 1989 to
determine the effectiveness of the maintenance program by
applying Maintenance Tree methodology to the licensee's
activities. The team found that the maintenance process for
San Onofre was well defined and incorporated many current
industry initiatives, reflecting strong management support and
involvement. The team also considered that implementation of
the program was satisfactory, but could be further streng
thened. This was evidenced by several examples of inattention
to detail in the development of maintenance work plans, failure
to fully implement all steps of maintenance work instructions,
12
poor or untimely root cause analyses, and insufficiently
developed or comprehensive corrective action plans. In
addition, a weakness was also noted in pre-job walkdowns by
planners. An example of this included the hydrogen fire that
occurred during maintenance work on a waste gas relief valve.
The licensee acknowledged these weaknesses and was addressing
their resolution.
The maintenance team considered the licensee's training and
qualification program to be well defined and to exceed
established industry training criteria. The program provided
good scheduling, documentation, feedback mechanisms, involve
ment of instructors in field activities, and training of
supervision. In addition, the resident inspectors found the
licensee's maintenance training facility to be well equipped
for hands-on training. With respect to staffing, the
maintenance team considered staffing for activities to be
satisfactory, with some reservation regarding the adequacy of
resources to address the workloads of work planners.
During this period, there were several operational events which
occurred as a result'of errors in the Maintenance/Surveillance
functional area. In particular, a reactor trip in Unit 3
resulted from a non-1E uninterrupted power supply (UPS) fault
because a temporary grounding cable was not removed upon
completion of work performed during a previous SALP period
(June 1988). In addition, several engineered safety feature
(ESF) inadvertent actuations (other than emergency core cooling
systems) occurred during the performance of surveillances as a
result of personal error or equipment failure. These events
were properly identified and analyzed, and were promptly
reported where required.
Nine severity level IV violations and two deviations were cited
in the Maintenance/Surveillance area during the assessment
period. However, none of these indicated a programmatic
breakdown and the licensee's root cause and corrective actions
were effective and timely in most cases as evidenced by lack of
recurrence.
2. Conclusion
Performance Assessment -- Category 1
3. Board Recommendations
The Board recommends that the licensee continue to improve
implementation of the maintenance program, especially regarding
attention to detail and procedural implementation. Efforts
should also continue to strengthen the work order preparation
and planning processes. Furthermore, the licensee should
continue to strengthen supervisory review of maintenance
13
activities to assure that they are performed safely and
efficiently.
1. Analysis
During this assessment period 180 hours0.00208 days <br />0.05 hours <br />2.97619e-4 weeks <br />6.849e-5 months <br /> of inspection effort
were devoted to assessing the licensee's emergency preparedness
program. This included two routine inspections and observation
of the 1988 and 1989 annual exercises. The licensee received a
SALP category 1 rating in this area during the last appraisal
period. The last SALP board encouraged improvement in the
areas of training and quality assurance.
Strengths identified during this assessment included upper
level management's continued support of the emergency
preparedness program. The only weak areas identified duri'ng
this assessment involved minor repeat exercise findings during
the 1989 exercise and some need for improvement in the shift
crew's familiarization with the Emergency Plan implementing
procedures. The licensee has been responsive to NRC concerns
in these areas and has implemented improvements to the Training
Program.
Management commitment to the Emergency Preparedness program was
demonstrated by continued support of and participation in the
licensee's drill and exercise program, and by significant
improvements to the licensee's emergency facilities, including
a new corporate support center, improvements to the Unit 1
operations support center, and improved telephone and compu
terized message systems. The actions by the Nuclear Affairs
and Emergency Planning (NA&EP) Department to cultivate a
cooperative interface with offsite agencies, including local
governments, the state of California, and the U. S. Marine
Corps, were also noted. This effort resulted in commendable
participation by these agencies during the 1989 exercise, even
though resources were then being expended in support of the San
Francisco Earthquake and a large forest fire in the area.
The licensee's efforts to resolve technical issues from a
safety standpoint have been conservative. For example, the
licensee initiated a program to perform root cause analyses on
all 1989 drill and exercise findings in an effort to improve
performance and resolve previous exercise weaknesses.
Licensee management has demonstrated responsiveness to NRC
initiatives. In response to Generic Letter 89-15, the licensee
volunteered to participate in the NRC's Emergency Response Data
System (ERDS). In addition, items identified by the NRC have
been evaluated by management and acted upon. During the exit
meeting for the 1989 exercise, several comments were brought to
licensee management's attention for their consideration. The
14
licensee received the comments in a cooperative manner and
responded promptly in writing by describing their evaluation
and corrective actions. During another inspection conducted in
1989, it was noted that the shift crews' familiarity with their
emergency procedures for classification and protective actions
were in need of improvement. To this end, the licensee has
provided a new full-time individual to the training program
with expertise in emergency planning. This individual is to
improve interface with the shift crews to increase their
familiarity with their implementing procedures and provide
feedback to Emergency Planning. The position also interfaces
with the managers of other disciplines, including Health
Physics and Maintenance, to insure their feedback and support
of the drill and exercise program.
The licensee's audit program for the Emergency Preparedness
area meets the regulatory requirements contained in 10 CFR
50.54(t) and was also noted to have improved in 1989. However,
inspection findings shortly after the end of the assessment
period indicated some weaknesses in the audit program.
Operational events were appropriately classified and no
violations of NRC requirements were identified in the Emergency
Preparedness functional area during this SALP period.
One Licensee Event Report (LER) was identified in the
Emergency Preparedness area. This LER dealt with improper
placement of fuse blocks for the emergency siren transfer
switch.
The licensee continues to maintain adequate staffing levels
with dedicated personnel to provide for the advancement of the
Emergency Preparedness Program and to sustain a cooperative
interface with local offsite agencies. Positions are ident
ified and authorities and responsibilities are well defined.
Few vacancies have occurred, and staffing continuity is
considered a strength. Expertise is available "in house";
consequently, there has been little need for outside contractor
support.
The licensee's training program is well defined, and utilizes
computer-based training supplemented by an ambitious quarterly
drill and exercise program. The drill program was observed to
have been improved during this SALP period by the utilization
of more challenging scenarios.
Increased emphasis was also
placed on the documentation of drill and exercise findings and
on the program to identify the cause of the finding to preclude
recurrence. Weakness was observed, however, in the licensee's
exercise critique program. As discussed during the NRC exit
for the 1989 exercise, providing the players with a copy of the
scenario prior to the critique may provide benefits.
15
2. Conclusion
Performance Assessment -- Category 1
3. Board Recommendation
Continued support of the licensee's drill and audit programs is
recommended to improve the implementation of corrective actions
and reveal areas for improved performance.
E. Security
1. Analysis
During this SALP assessment period, Region V conducted three
physical security inspections and one material control and
accountability (MC&A) inspection at the San Onofre Nuclear
Generating Station. Approximately 310 hours0.00359 days <br />0.0861 hours <br />5.125661e-4 weeks <br />1.17955e-4 months <br /> of direct
inspection effort (including 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> for MC&A) were expended
by regional inspectors. In addition, resident inspectors
provided continuing observations in this area.
Corporate and plant management continued to be involved in
assuring quality and in reviewing the operation of the overall
security program. This remained a strength, as in the previous
SALP period. This was further reflected in the licensee's
approach to the identification and resolution of technical
issues from a safety, as well as a security, standpoint.
Two violations, one licensee identified and not cited, were
indicated during the SALP period. One violation pertained to
an item of security equipment required to be protected as vital
being located outside vital areas, and the other pertained to
an individual being allowed access to a vital area without
appropriate processing. Both appeared to be isolated incidents
not previously encountered by the licensee. The licensee
reported 13 events, of which four pertained to security and
nine pertained to Fitness for Duty incidents.
The licensee submitted copies of the safeguards event log on a
quarterly basis as required, indicating a total of 411 logged
security events attributed to both human and hardware failures.
The licensee empaneled a Security Section Safeguards Event
Review Committee to meet regularly and review each of the
logged events. Trends were established and responsibility was
assigned to an appropriate individual for each type event to
perform the necessary study, design, engineering, construction,
training, or other action necessary to correct the problem and
preclude or reduce its recurrence.
Performance appeared mixed in the area of responsiveness to NRC
initiatives during the period. On one side, licensee action in
response to an NRC generic letter (requiring licensees to plan
16
to react to a vehicle bomb threat against their facility)
appeared outstanding. The licensee not only went to great
lengths to ensure a thorough and comprehensive response to such
a threat, but went on to physically test the entire response
plan and all elements. On the other hand, response to NRC
initiatives or findings pertaining to vital area (VA) barriers
at the site appeared less prompt. An NRC information notice
issued in 1987 advised all licensees to review their VA
barriers for suspected penetrations to assure conformance to
existing requirements. The licensee did an excellent job in
reviewing barriers and properly identified a number of openings
or penetrations through the barriers. Several of these
openings were concluded to require corrective measures. This
corrective action has been ongoing and is currently programmed
for completion during the next SALP period. Similarly, an NRC
Regulatory Effectiveness Review (RER) indicated weaknesses in
Unit 1 VA barriers in 1985. At that time, the licensee
concluded that the barriers had "been formally reviewed and
approved as described in the San Onofre Physical Security Plan"
and that the continued use of such barriers was reasonable. At
the end of this SALP period, the licensee indicated that they
would again review these barriers to assess the RER-indicated
weaknesses for possible amelioration.
Licensee staffing of the security program has been a strength
during this period as it was during the previous SALP period.
Personnel appeared to be carefully screened for experience and
training. The security organization appeared well defined,
with areas of responsibility and authorities appropriately
detailed. Decision making authority appeared to be properly
delegated to assure quick identification of and response to
problems and changes. A program of security manning reductions
was initiated during this SALP period. As of the end of 1989,
14 personnel reductions had been made in the security
organization, with a goal of 21 by the end of 1992. The
licensee indicated that these reductions are being closely
reviewed and managed to ensure that there is no impact on
compliance or security organization commitments.
Remaining a strength from the previous SALP period was the
licensee's security training and qualification program.
Instructors appeared highly qualified and motivated. The
licensee has also recently enhanced security training for armed
personnel by encouraging quarterly practice firing of assigned
response weapons.
2. Conclusion
Performance assessment -- Category 1
17
3. Board Recommendations
The Board recommends that the licensee continue to support
security program enhancements; e.g., the licensee initiative to
assess and ameliorate Unit 1 Vital Area barrier weaknesses.
F. Engineering/Technical Support
1. Analysis
During the SALP period, approximately 330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br /> of direct
inspection effort were applied in the Engineering and Technical
Support area. In addition to this inspection effort by
resident and region-based inspectors, an NRC Safety System
Functional Inspection (SSFI) team performed an inspection of
Units 2 and 3. The major strength identified during this
assessment period was the licensee's aggressiveness toward
upgrading programs to enhance engineering and technical
performance. The major weaknesses in this functional area
involved inadequate translation of the design bases to com
ponent setpoints, and the lack of formal calculations for key
design parameters related to some electrical distribution
systems. In addition, there were a few examples of problems
with design change output that resulted in plant events.
In response to problems identified in this area during the last
SALP, licensee management initiated many enhancements to
improve engineering performance and the quality and complete
ness of design basis documentation. The Nuclear Engineering,
Safety, and Licensing (NES&L) organization was reorganized and
relocated to Irvine to enhance the effectiveness of the
engineering organization in communicating with the site. In
addition, the licensee was increasing the in-house design
effort to minimize the use of contractor engineering support,
and was expecting that all engineering work for the 1990 Unit 1
refueling outage would be performed in-house. An Engineering
Excellence program was also implemented during this assessment
period to promote development of engineering standards, expand
and formalize design review functions, improve communications
and work processes, enhance design engineer training programs,
and monitor the results of engineering work to assess the
degree of quality improvements.
The licensee also instituted a program for enhanced under
standing of the design basis. This design basis document (DBD)
review will include a review of the design basis for selected
systems and a design document transfer from vendors to SCE.
The licensee expects that approximately 94 systems and topical
areas will have been reviewed when the DBD effort is completed
after about five years.
With respect to design changes, problems became evident in the
middle of the assessment period due to three events related to
18
instrumentation upgrades performed during the Cycle X refueling
outage in Unit 1. These were (1) a reactor trip during restart
caused by electrical circuit noise in the new nuclear
instrument (NI) system (reflecting insufficient analysis of
conditions observed before startup); (2) an automatic actuation
of the auxiliary feedwater (AFW) system (because engineers
overlooked the dynamic flow effects in the steam generator and
had not properly involved the nuclear steam system supplier in
the design process); and (3) a manual reactor trip which had to
be initiated because of a loss of feedwater flow (due to
failure to properly reflect design change information in
surveillance procedures).
To improve engineering output, the design change process was
being revised to better define the scope of work and to provide
for more thorough reviews of each change from its initial
conception to final approval.
This program should be fully
implemented for the Unit 1 Cycle XI refueling outage scheduled
for the summer of 1990. Although the design change process was
still in transition at the end of the assessment period, it
appeared that the performance of design changes was under
effective control.
Staffing appeared to be strained at times during the assessment
period, as evident by the amounts of overtime used. However,
additional engineering personnel had been added by the end of
the period, in support of the licensee's efforts to assume a
stronger in-house engineering role.
The licensee was actively participating in industry efforts to
improve the scope and content of training for the design
engineering staff and has developed a Nuclear Engineering
Organization training plan. The licensee also developed a
cognizant (plant technical) engineer training program during
the period. Both training programs consist of general and site
specific training designed to provide information for all
disciplines. These actions were notable, although somewhat
slow in implementation.
The November 1989 electrical SSFI conducted for Units 2 and 3
identified a number of specific deficiencies and two general
areas of weakness in this functional area. These involved
(1) weaknesses in the translation of design bases into com
ponent setpoints (e.g., diesel day tank level setpoints that
were below the TS requirements), and (2) lack of formal
calculations for key design parameters related to several
electrical distribution systems (e.g., missing or inadequate
calculations for diesel generator load, 120 VAC control power
voltage regulation, and containment penetration sizing and
protection). Calculations also did not show that the D/G air
receivers had sufficient capacity to support five automatic
starts (an FSAR commitment).
19
The NRC maintenance inspection team reviewed several engineer
ing evaluations and found them to be adequate. The team con
sidered that the engineering/technical support program and its
implementation were satisfactory. However, some weaknesses
were noted in engineering performance, as evidenced in insuf
ficient design data or analyses. In addition, insufficient
attention to detail was noted involving pressure ranges used in
calibration of feedwater flow transmitters.
Weaknesses in safety evaluations were noted in several cases.
For example, during startup from the Unit 1 Cycle IX refueling
outage, the licensee determined that no unreviewed safety
question (USQ) existed for S/G tube sleeve deficiencies.
However, this determination was made without an assessment of
the thermal hydraulic response of an improperly sleeved tube
and the potential consequences during a steam line break ,
accident. A subsequent assessment during the Cycle X refueling
outage showed that operation in this manner was a USQ. A
second example concerned a safety evaluation for an inadequate
weld process that resulted in several leaking S/G tube plugs in
Unit 2. In this case, an evaluation was not prepared to
substantiate return to operation without repairing other plugs
that had potential for similar weld deficiencies. By the end
of this assessment period, the licensee was focusing attention
to improve the quality of safety evaluations.
NRC inspections identified one violation and two deviations in
this functional area, but these did not indicate significant
weaknesses. A total of 29 LERs were associated with
Engineering and Technical Support activities. Most of these
involved system design inadequacies or personnel errors in the
engineering process that led to deficiencies which were
primarily found in Unit 1. Many of these LERs reflected
deficiencies in early design work which were identified through
more aggressive efforts by engineering to verify the design
basis of systems, or by a more critical attitude during the
performance of design work. These efforts identified a number
of significant design inadequacies such as Unit 1 safety
injection alignment delays and a lack of backup nitrogen for
recirculation system and containment spray system valves.
2. Conclusion
Performance assessment -- Category 2
3. Board Recommendations
The Board recommends that the licensee continue to emphasize
the design basis update program and strengthening of in-house
engineering capabilities. In addition, efforts to improve
engineering and technical work should continue, and the
licensee should ensure that calculations in support of
20
setpoints and key design parameters of systems are accurate and
properly maintained.
G. Safety Assessment/Quality Verification
1. Analysis
During the SALP period, approximately 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> of direct
inspection effort were applied in this functional area. The
major strength identified during this assessment period was the
licensee's aggressiveness in upgrading programs to enhance
performance in this area. In addition, enhancements were made
in the communication of problems to the NRC. Weaknesses in
this functional area were associated with the adequacy of the
corrective action program, safety evaluations, and licensing
submittals.
In response to findings during the last SALP period, the
licensee implemented or upgraded several programs to enhance
performance in this area. The area monitoring program (AMP)
was enhanced to provide a systematic method for directly
observing the implementation of QA program requirements so that
all oversight organizations could participate in monitoring
activities. This included evaluations of material condition,
temporary modifications, and housekeeping of assigned areas.
In addition, monitoring programs were implemented to provide
more direct observation of work performance, and resulted in
meaningful findings (e.g., problems with pipe supports in the
turbine building). These programs reflected a more
performance-based review by quality oversight groups.
Increased presence of quality oversight personnel and
management was noted in the plant, and the remaining offsite
safety oversight groups were relocated to the site to enhance
their effectiveness.
The QA audit and surveillance programs were revised during this
period to focus more directly on performance. Audit plans
received more in-depth reviews, and the scope of audits was
better defined. Followup documentation for audits and
surveillances provided a more thorough evaluation of conditions
found during the review, and corrective action requests were
issued for findings.
Problems identified included inadequate
control of crimpers and improper overpressure mitigation system
setpoints for the Unit 1 power-operated relief valves.
Although these programs appeared to be developing well,
problems such as non-conservative TS interpretations by
Operations or deficiencies with the corrective action program
(discussed below) were not challenged by QA until after the NRC
raised concerns in these areas.
The licensee focused increased emphasis on training and
qualification, with particular emphasis on quality assurance
personnel.
All auditors and inspectors, including quality
21
control inspectors, were given additional training on the
conduct of performance based inspections. This training,
coupled with increased in-plant inspections and focus on
safety-significant matters, reflected substantial management
support for the enhancement of performance in this area.
Higher management expectations and identified weaknesses in
knowledge levels resulted in downgrading of the qualifications
of approximately 30% of the auditors. Retraining of the
personnel was in progress through the use of an auditor
certification program, which was implemented to enhance the
knowledge level of new personnel and to recertify previous
auditors. Staffing was also enhanced in most quality oversight
groups. This included raising the experience base by adding
some licensed operators and other experienced personnel to the
quality assurance organization.
The root cause assessment program was in the process of being
enhanced to increase effectiveness. Although root cause
assessments will continue to be performed largely by the
cognizant organizations, overall program responsibility was
assigned to the Manager of Oversight Engineering. This new
position was established within the Oversight Organization to
provide the methodology, training, and assistance for root
cause determinations, and to provide oversight of root cause
determinations conducted by the other organizations. This
manager will also direct the efforts of the Independent Safety
Engineering Group, the Nuclear Safety Group, and the Quality
Engineering Group. Although progress was initially slow,
momentum had been established by the end of the SALP period,
and this program is expected to be fully implemented by the
spring of 1990.
The maintenance team inspection found a number of examples of
weaknesses in this functional area. These examples included
weak root causes for several problem reports, excessive use of
the category "unknown" (in classifying root causes for some
nonconformance reports), and insufficient priority for and
tracking of the resolution of several NRC inspector-identified
findings, particularly involving in-service inspection (ISI)
issues in Unit 1. The licensee was actively pursuing
corrective actions to resolve these problems, as discussed
previously.
A problem concerning a solenoid valve failure (Unit 1 valve
CV-304) that resulted in a diversion path for hot leg
recirculation flow led to the identification of a number of
weaknesses with the licensee's corrective action program.
Reviews by the resident inspectors and the licensee's QA
organization found a number of related problems, including
inadequate dissemination of information about component
problems to the necessary organizations for review, lack of
timely resolution of root cause determinations, inadequate
follow-through on commitments made in LERs, improper oversight
22
of outstanding items, and inadequate review of component
failures for generic implications. In addition, it was noted
that the licensee did not routinely evaluate site component
problems for 10 CFR Part 21 applicability. The QA organization
performed an in-depth analysis of this issue and found
additional problems with the corrective action program. The
licensee was aggressively pursuing resolution of these issues.
A weakness was also identified with inadequate or non-conser
vative safety evaluations performed during the period. For
example, the licensee did not promptly document a wall thick
ness problem involving residual heat removal (RHR) system
piping (a condition identified by ultrasonic measurements), and
a 10 CFR 50.59 review for changes to the intermediate range
startup rate trip did not result in the submission of a
required TS amendment request for. system change which blocked
the trip function at less then 10 % power. The licensee was
working to enhance safety evaluations and was in the process of
implementing the associated guidance provided in Nuclear Safety
Analysis Center (NSAC)-125.
Problems were noted with the adequacy and control of LERs. In
particular, there were three LERs early in the period that did
not appear to have fully addressed the applicable root causes
and corrective actions for the associated events. In addition,
it was identified in association with the CV-304 solenoid valve
failure (discussed previously) that a relatively large number
of LERs requiring supplemental reports were long outstanding.
LER quality improved toward the end of the assessment period,
and the licensee was attempting to reduce the backlog of
supplemental LER reports due to the NRC.
Licensing submittals received at the beginning of the period
were at times lacking in thoroughness and depth, resulting in
the need for repeated submittals to and conferences with the
NRC.
Examples included the single failure analysis submittal
for the Unit 1 reactor protection system (RPS) and engineered
safety features (ESF), and the Unit 1 thermal shield degrada
tion submittal. In addition, the NRC noted instances of the
licensee's inability to adequately identify, plan, and track
licensing actions. Examples included the Units 2 and 3 spent
fuel pool re-racking amendment, and the Unit 3 low temperature
overpressure (LTOP) mitigation system amendment. Also, there
were delays in submitting many licensing documents and related
correspondence throughout the period. Improved quality of
licensing submittals was noted toward the end of the assessment
period. Among these was the licensee's October 2, 1989
submittal which addressed full term operating license (FTOL)
open items. In this submittal, the licensee provided a
schedule for resolution of these items. In addition, at their
own initiative, the licensee committed to make improvements to
both the recirculation portion and the injection portion of the
safety injection system.
23
During this period one level V and four level IV violations
were identified, but these did not indicate significant flaws
in the licensee's programs.
2. Conclusion
Performance assessment -- Category 2
3. Board Recommendations
The Board recommends that the licensee continue to implement
and improve the root cause assessment program. In addition,
efforts to improve 10 CFR 50.59 safety evaluations and the
corrective action program should continue to ensure that
problems are adequately and timely resolved. Continued efforts
should be devoted to ensuring that conservatism is exhibited in
the making of operational decisions. Continued emphasis should
also be given to the quality and timeliness of licensing
submittals.
V. SUPPORTING DATA AND SUMMARIES
A. Licensee Activities
In general, all three units operated satisfactorily during the
assessment period and were relatively free of problems. Specific
operational activities were as follows:
Unit 1
Unit 1 began the Cycle X refueling outage in November, 1988.
Some
of the major plant modifications completed during that outage
included the installation of a new nuclear instrumentation system
(NIS), reconfiguration of the auxiliary feedwater (AFW) system to
include a dedicated safe shutdown train, installation of upgraded
steam generator (S/G) instrumentation, and upgrades to other systems
which were identified as being vulnerable to single failure. The
licensee attempted to return the Unit to service in May, 1989;
however, a number of difficulties were encountered over a period of
three months. Those difficulties included the following:
-
An automatic reactor trip (while in Mode 2) due to electrical
noise in the newly installed NIS;
-
A manual shutdown during power ascension due to a level anomaly
in the modified S/G instrumentation, which resulted in an
automatic initiation of AFW;
-
A manual shutdown from power to repair the cause of a high
bearing temperature in one of the reactor coolant pumps (RCPs);
-
A manual trip from power when a loss of feedwater occurred
during a surveillance test;
24
- -
An automatic trip from an erroneous reactor coolant system low
flow signal, caused by a grounded instrument cable; and
-
A manual trip when multiple rods dropped into the core due to
faulty relays.
After these problems were corrected (each in turn) the Unit operated
trouble-free at power from September through November, at which time
it was shut down to make modifications to the hot leg recirculation
flow path (after design deficiencies were identified). After the
Unit was returned to service, it was again shut down in December to
correct problems with backup nitrogen for a safety injection valve.
The Unit was subsequently restarted and operated at power through
the remainder of this assessment period.
Unit 2
Unit 2 operated at power from the beginning of this SALP period
until January 1989, when it was shut down to repair an AFW pump
motor. The Unit was restarted in February even though lighted
annunciators indicated all four Core Protection Calculators (CPCs)
to be inoperable. This was recognized by operators during the
startup, and a shutdown was initiated. The CPCs were fully
operable, however, and initiated a reactor trip as the reactor was
being shut down (because operators did not place the trip function
in bypass). After restart, Unit 2 operated at power until May 1989
when it was shut down to repair a S/G tube leak. The Unit was
subsequently returned to service in June and was operated at power
until September, when it was shut down for the Cycle V refueling
outage. As the reactor was being shut down for the refueling
outage, it had to be manually tripped from 25% power when operators
realized that the axial shape index was approaching the CPC
automatic trip setpoint. A number of major activities were per
formed during the 97-day refueling outage, including the following:
-
Control room modifications for human factors improvements;
-
Turbine overhaul;
-
Installation of an anticipated transient without scram (ATWS)
diverse reactor trip;
-
Overhaul of main feedwater heaters; and
-
Main transformer replacement.
In December 1989, shortly after startup following the refueling
outage, the Unit was shut down to repair a main feedwater flow
venturi flange leak. The Unit was then returned to service and
operated at power through the remainder of this assessment period.
25
Unit 3
Unit 3 was operating at power at the beginning of this period. An
automatic reactor trip occurred in January 1989, due to a low S/G
level caused by a loss of non-1E power for the feedwater controller.
After return to service from the short outage, the Unit operated
until April 1989, when it tripped automatically due to a low voltage
condition associated with power to the control element drive
mechanism relays. After return to power operation, the Unit was
shut down in July to repair a low pressure safety injection (LPSI)
pump seal leak. After the return to service following this repair,
the Unit operated continuously at power for the remainder of this
assessment period. Shortly after the end of this SALP period, the
Unit exceeded the site's continuous operation record of 218 days set
by Unit 1 in 1976.
B. Direct Inspection and Review Activities
Approximately 6570 inspection hours were expended during this
assessment period in performing a total of 46 inspections by
resident, region-based, headquarters, and contract personnel.
Inspection activity in each functional area is summarized in
Table 1.
C. Enforcement Activity
Three resident inspectors were onsite during the SALP assessment
period. A total of 46 inspections, including a maintenance team in
June and July 1989, and an electrical SSFI in October and November
1989, were conducted during this period for a total of 6395 inspec
tor hours (plus 259 hours0.003 days <br />0.0719 hours <br />4.282407e-4 weeks <br />9.85495e-5 months <br /> invested in exit and management meetings).
A summary of inspection activities is provided in Table 1, along
with a summary of enforcement items identified during these inspec
tions. A description of enforcement items is provided in Table 2.
A synopsis of licensee event reports is included as Table 3.
D. Confirmation of Action Letters
One Confirmation of Action Letter was issued during this assessment
period, on January 31, 1989. This letter confirmed the licensee's
plans to resolve questions regarding Unit 1 thermal shield integrity
and other technical issues, and to obtain NRC concurrence before
restart of Unit 1 from its Cycle X refueling outage.
E. Orders
An Order requiring full compliance of Unit 1 with Generic Letter 82-28, "Inadequate Core Cooling Instrumentation System" was issued
on May 5, 1989.
An Order Confirming Licensee Commitments On Full-Term Operating
License Open Items For Unit 1 was issued on January 2, 1990. This
order confirmed SCE's commitment to complete the full-term operating
26
license open items pursuant to the schedule described in a letter
from the licensee dated October 2, 1989. In addition, this Order
modified the NRC's previous order dated May 10, 1989, to require
that the reactor vessel level indication system be installed during
the Cycle XII refueling outage instead of the Cycle XI refueling
outage. This Order also confirmed that the licensee would conduct a
S/G tube inspection during the Cycle XI refueling outage.
F. AEOD Assessment of Licensee Event Reports
A review of licensee events at San Onofre, performed by the Office
for Analysis and Evaluation of Operational Data (AEOD), is included
as Attachment 1. AEOD reviewed the LERs and significant operating
events for quality of reporting and effectiveness of identified
corrective actions.
TABLE 1
INSPECTION ACTIVITIES AND ENFORCEMENT SUMMARY
Enforcement Items*
Functional
Inspection
Percent
Severity Level
Area
Hours
of Effort
I II III
IV V Dev
A.
Plant Operations
1772
26.7
5
B.
Radiological
530
8.2
2
Controls
C. Maintenance/
1751
26.7
9
2
Surveillance
D.
Emergency Prep.
180
2.7
E.
Security
310
4.7
1
F.
Engineering/
332
5.2
1
2
Technical Support
G. Safety Assessment/ 1697
25.8
4 1
Quality Verif.
Totals
6572
100.0
22
1 4
Severity levels are discussed in 10 CFR 2, Appendix C.
In addition, 259 hours0.003 days <br />0.0719 hours <br />4.282407e-4 weeks <br />9.85495e-5 months <br /> were expended in exit and management meetings.
This information is current through inspection reports 206/90-05;
361/90-05; and 362/90-05.
TABLE 2
ENFORCEMENT ACTIVITY
UNIT 1
Inspection
Severity
Functional
Report No.
Subject
Level
Area
88-24
Inadequate Control of Maintenance
IV
C
Activities on Environmentally
Qualified Equipment
88-28
Failure to Use Proper Procedure
IV
C
Revision for Performing Reactor
Coolant Chemistry Sampling
89-01
Failure to Comply with Foreign
IV
C
Material Exclusion Control
Requirement
89-03
Inadequate Nonconformance Report
IV
G
on Residual Heat Removal Pipe
Wall Thickness
89-08
Inadequate Control of Radioactive
IV
B
Material
89-09
Inadequate 10 CFR 50.59 Review
IV
G
Regarding Nuclear Instrumentation
System Block of Start-up Rate Trip
89-16
Emergency Lighting Not Performed
Dev
F
Per Updated Final Safety
Analysis Report
89-16
Nonconformance Report Failed to
IV
F
Identify Root Cause
89-16
Failure to Perform Calibration
IV
C
and Test
89-18
Temporary Cables Routed With
IV
C
Safety Related Cable Trays
89-28
Failure to Verify or Properly
IV
B
Maintain a Procedure for
Respirators #
89-31
Inadequate Corrective Actions
IV
G
Related to Failure of Automatic
Switch Corporation Solenoid Valves
-2
.
Table 2, Enforcement Items (Continued)
UNIT 1
Inspection
Severity
Functional
Report No.
Subject
Level
Area
89-31
Failure to Comply with Technical
IV
A
Specification 3.0.3 by Initiating
Plant Shutdown Within One Hour
When Normal Hot Leg Recirculation
Flow Path Inoperable
90-01
Failure to Resolve Issues of In-
Dev
C
service Testing Program For Pumps
Bounded By the Safety Analysis #
Applies to Units 1, 2, and 3
UNIT 2
Inspection
Severity
Functional
Report No.
Subject
Level
Area
88-25
Inadequate Calibration Program
IV
C
for Safety Related Alarm
Devices ##
89-06
Failure to Report Condition that
V
G
Resulted in Violation of Techni
cal Specification Requirements ##
89-09
Housekeeping in 2/3 Electrical
IV
C
Cabinets and Electrical
Maintenance (Unit 3) ##
89-11
Adequacy of Corrective Actions
IV
G
Regarding 10 CFR 50.49 Equipment
Qualification Discrepancy ##
89-16
Work Authorization Request
IV
C
Released Improperly and Poorly
Maintained
89-18
Atmospheric Dump Valve Inoperable
IV
A
for Automatic Operation
89-24
Failure to Declare Equipment
IV
A
Inoperable Due to Delinquent
Surveillance
-3
Table 2, Enforcement Items (Continued)
UNIT 2
Inspection
Severity
Functional
Report No.
Subject
Level
Area
89-24
Lack of Control Over Temporary
IV
C
Cables Routed through a Control
Room Emergency Air Cleanup
System Door ##
89-30
Failure to Implement Periodic
Dev
C
Ground Check on Reactor
Protective System and Engineered
Safety Feature Actuation System
89-33
Excessive Overtime Usage
IV
A
90-03
Security Equipment (Required To
IV
E
Be Protected) Located Outside
Vital Area
.
- Applies to Units 2 and 3
UNIT 3
Inspection
Severity
Functional
Report No.
Subject
Level
Area
89-06
Failure to Control Technical
IV
A
Specification Fire Doors
89-16
LPSI Pump Seal Leakage
Dev
F
Drain Piping Not Installed As
Indicated in the Updated Final
Safety Analysis Report
Functional Areas
A -
Plant Operations
B - Radiological Controls
C - Maintenance/Surveillance
E -
Security
F -
Engineering/Technical Support
G - Safety Assessment/Quality Verification
S P
O T A B L E 3 A - U n i t 1
SYNOPSIS OF LICENSEE EVENT REPORTS (LERs)
Functional
SALP Cause Code*
Area
A
B
C
D
E
X
Totals
A.
Plant Operations
4
7
11
B.
Radiological
2
2
Controls
C. Maintenance/
2
3
5
Surveillance
D. Emergency Prep.
1
1
E.
Security **
8
1
9
F.
Engineering/
7
14
1
22
Technical Support
G.
Safety Assessment/
1
1
Quality Verif.
Totals
23
14
5
9
51
- Cause Code
A - Personnel Error
B - Design, Manufacturing or Installation Error
C -
External Cause
D - Defective Procedures
E - Component Failure
X -
Other
Security LERs are applicable to Units 1, 2, and 3, and include Fitness
for Duty (FFD) reports. As of January 3, 1990, FFD events are not
reportable as safeguards events (are reported pursuant to 10 CFR 26.73).
Functional Areas
A -
Plant Operations
B -
Radiological Controls
C - Maintenance/Surveillance
D -
E -
Security
F -
Engineering/Technical Support
G -
Safety Assessment/Quality Verification
The above data are based upon LERs 88-15 through 90-03.
TABLE 3B -
Unit 2
SYNOPSIS OF LICENSEE EVENT REPORTS (LERs)
Functional
SALP Cause Code*
Area
A
B
C
D
E
X
Totals
A.
Plant Operations
9
4
3
2
3
21
B.
Radiological
1
1
Controls
C. Maintenance/
3
1
2
6
Surveillance
D.
Emergency Prep.
E.
Security **
4
4
F. Engineering/
1
4
5
Technical Support
G.
Safety Assessment/
1
1
Quality Verif.
Totals
17
9
5
4
3
38
- Cause Code
A -
Personnel Error
B - Design, Manufacturing or Installation Error
C -
External Cause
D - Defective Procedures
E - Component Failure
X -
Other
One Security LER is applicable to Unit 2 only; the remaining three are
applicable to Units 2 and 3. Security LERs include Fitness for Duty
(FFD) reports. As of January 3, 1990, FFD events are not reportable as
safeguards events (are reported pursuant to 10 CFR 26.73).
Functional Areas
A -
Plant Operations
B -
Radiological Controls
C - Maintenance/Surveillance
E -
Security
F - Engineering/Technical Support
G - Safety Assessment/Quality Verification
The above data are based upon LERs 88-27 through 89-23.
TABLE 3C - Unit 3
SYNOPSIS OF LICENSEE EVENT REPORTS (LERs)
Functional
SALP Cause Code*
Area
A
B
C
U
E
X
Totals
A. Plant Operations
1
3
1
1
6
B. Radiological
1
1
2
4
Controls
C. Maintenance/
2
1
3
Surveillance
D. Emergency Prep.
E. Security
F. Engineering/
2
2
Technical Support
G. Safety Assessment/
Quality Verif.
Totals
4
4
3
3
1
15
- Cause Code
A
Psonnel Error
B - Design, Manufacturing or Installation Error
C - External Cause
D - Defective Procedures
E - Component Failure
X -
Other
Functional Areas
A - Plant Operations
B - Radiological Controls
C -
Maintenance/Surveillance
D -
E - Security
F - Engineering/Technical Support
G -
Safety Assessment/Quality Verification
The above data are based upon LERs 88-09 through 90-01.
ATTACHMENT 1
ANALYSIS OF LICENSEE EVENT REPORTS (LERs)
PREPARED BY THE
OFFICE FOR ANALYSIS AND EVALUATION OF OPERATIONAL DATA
Erclcsure
AEOD Input to SALP Review for San Onofre Unit 1
During the assessment period of October 1, 1988, to January 31,
1989, 34 LERs
were submitted to the NRC. Our review encompassed LERs 88-15 through 89-2F.
1. Important Operating Events
Utilizino AEOD's screening process, the following 14 Unit 1 LERs were categorized
as important events:
LER 88-18: The structural integrity of 156 sleeved steam generator tubes might
not have been in accordance with design requirements from the time
they were installed in 1981 until they were plugged in December
1988. Eddy current testing methods, utilized at the time of sleeve
installation, did not detect inadequate tube roll expansions.
State-of-the-art eddy current testing technology was utilized to
identify the problem tubes.
(Event date: 12/12/88).
LER 88-19:
Design deficiencies existed in the Train "B" automatic controls
for the electrical power distribution system. Upon actuation of
certain safeguard systems, unqualified non-safety related loads
would not be isolated from the safety related portions of the
distribution system. This condition could electrically overload
the emergency diesel generator. With a main steam lire break
occurring in certain locations outside containment, spurious
actuations and malfunctions of non-safety related loads could
result in Train "A" voltage degradation and failure of the safety
related Train "A" loads to start.
The design deficiencies were caused by placing excessive reliance
on multiple contractors, and the lack of programs to compile,
update, and verify design basis documents. A training program for
supervisory personnel performing the review of engineering and
technical work was initiated.
(Event date:
12/13/88).
LER 88-20: Design requirements of post-TMI Action Plan (NUREG-0737)
Item II.E.1.2, Part 2 were not fully implemented in the design of
the steam generator wide-range level indication system. The level
indicators (one per steam generator) were not powered from a
battery-backed electrical power source, and the associated level
transmitters, installed inside containment, were not environmentally
qualified. The level indication system serves as one of two means
providing auxiliary feedwater flow indication. The cause was
attributed to weaknesses in the licensee's commitment management
program. (Event date:
12/8/88).
LER 88-21: 8 of 33 contairment fire protection system spray nozzles were found
to be plugged, due to piping corrosion. Minor leakage of borated
water through a spray isolation valve might have accelerated the
-2
corrcsion. Corrective actions included blowing the system with air
to ensure corrosion products and blockage were completely removed,
replacing nozzles with a non-clocing type, and performing air flow
tests.
(Event date:
12/12/88).
LEP 89-01: Three reactor vessel thermal shield support block bolts were found
to be protruding from the inner surface of the core barrel in excess
cf normal tolerances. Failure of the bolts was believed to have
been caused by high-cycle flow induced vibration.
As corrective actions, accessible support features were inspected
by remote video camera, and an engineering analysis was performed
to support continued plant operation. Additionally, a conceptual
design and plan for restoring the thermal shield supports was
initiated. (Event date:
1/8/89).
LER 89-03:
In response to NPC Generic Letter 88-14, the licersee determined
that during a design basis LOCA, the component cooling water (CCW)
control valves to the RHR heat exchangers could fail open due to
either assumed 1) loss of instrument air or 2) loss of the electri
cal control power supply. This could result in a decrease in CCW
flow to the recirculation heat exchanger to a value below that
assumed in the safety analysis. Assuming a single failure which
renders two CCW pumps inoperable, the remaining CCW pump could
runout, creating a total loss of CCW.
The failure modes and effects analysis, performed in 1976, did
not recognize the effects of failure of the CCW control valves.
The licensee installed blocking devices on the control valves
to limit the degree to which they can open.
Flow tests were also
performed to verify adequate flow distributions of CCW with one
pump in operation. (Event date: 1/27/89).
LER 89-04: A design deficiency was identified ir the automatic loading circuitry
of the safety-related 4 kV buses. When the bus load sequencers
initiate in response to a safety injection signal concurrent with a
loss of offsite power, the loss of power latch is reset as soon as
the diesel generator output breaker closes and voltage to the bus
is restored. Consequently, if one bus is energized by a diesel
generator in a shorter time than the other diesel generator, the
loss of power latch in the load sequencer associated with the
lagging diesel generator will be reset, and the output of the
breaker for that diesel generator will not have the reouire logic
to close.
Deficiencies with engineering review, oesign basis documentation,
and post-modification testing caused the concern. A training
program for supervisory personnel was initiated, and a design basis
documentation program was established. (Event date: 3/2/89).
LER 89-07: Design provisions, intended to trip reactor in event of a reactor
coolant pump (RCP) locked rotor, did not satisfy single failure
criterion. The existing RCP over-current protection scheme was
set-up to trip the RCP after a 24 second time delay. The time delay
relay was not bypassed after the pump was running. Therefore, the
pump protection scheme would not respond to a locked rotor ccndition
for 24 seconds. Single failure analysis assumed the locked rotor
(high current) trip would occur within 6 seconds.
The RCP over current protection settings were not reviewed during
performance of the reactor protection system single failure analysis
performed in 1987.
Failure to detect the error resulted from
absence of clear design basis documentation.
(Event date: 2/27/F9').
LER 89-08: Containment fire suppression system pneumatic control valve CV-92
could fail open due to a single spurious failure of the solenoid
valve which controls CV-92. This failure could divert flow from
the containment spray system during a LOCA, and result in contain
ment pressure reaching a value greater than design pressure. The
single failure analysis of the ECCS, performed in 1987, did not
address failure of CV-92.
A design change was made to the CV-92 control circuitry to preclude
opening due to a single failure. A single failure re-analysis of
the ECCS and supporting systems was performed. A training program
for supervisory personnel was also initiated.
(Event date:
3/8/89).
LER 89-11:
Upon initiation of safety injection, the main feedwater pumps (MFPs)
realign to take suction from their respective SI trains and discharge
into the RCS. MFP minimum flow valves, assumed to close within 21
seconds following safety injection actuation with loss of offsite
power, would be delayed in closing due to wiring discrepancies,
contrary to safety analysis. Accordingly, delivery of safety
injection flow to the RCS would be below that assumed in the safety
analysis.
The cause of this condition was inadeouate implementation cf design
basis requirements. General engineering deficiencies, as described
in previous LERs, contributed to this situation. The minimum flow
system has been modified. (Event date:
3/23/89).
LER 89-14: Unlimited operation of the DC buses on cross-train chargers during
the period 1977 through early 1989 (as allowed by existing technical
specifications) was subsequently determined to have reduced the
reliability of the onsite emergency electrical system during
accident scenarios. In the event of a loss of offsite power,
concurrent with failure of an emergency diesel generator, having
the chargers previously aligned to the opposite trains could result
in reduction of battery voltage and loss of control power to the
other diesel generator within 90 minutes.
-4
Operation of the buses under these conditions was caused by failure
to develop appropriate technical specifications.
Design changes to separate the chargers have been completed.
Inadequate engineering and technical work were causes of this event.
(Event date: 4/5/89).
LER 89-24: The licensee deteriined that the plant could be placed in a
configuration which could result in degraded containment spray
system flow.
If the containment spray system flow restricting
valves were in a closed position, and a loss of non-safety related
instrument air occurred, the spray system would be unable to
perform its intended function. An emergency backup nitrogen supply
to open the valves upon loss of instrument air should have been
provided in the design.
Weak engineering design control and poor understanding of the
design basis of the valves contributed to the problem. Technical
specification changes were made to address the issue. Corrective
actions associated with engineering weaknesses were described in
similar LERs described above. (Event date:
9/29/89).
LER 89-25:
Similar to LER 89-24, it was determined that the primary hot leg
recirculation function was susceptible to loss of non-safety
related instrument air. Two valves in the hot leg recirculation
path would fail closed on loss of instrument air, resulting in a
condition where boron precipitation in the core region could
possibly occur. Weaknesses in licensing support to the plant were
identified as the root cause of the event. A nitrogen backup
supply to the instrument air system for the valves was added.
(Event date:
10/12/89).
LER 89-26:
Charging isolation valve CV-304 failed to close when provided with
a close sional, rendering the valve inoperable. Entry into
Technical
pecification 3.0.3 was required, as the appropriate
technical specification did not have an action statement for this
situation. However, the required entry into TS 3.0.3 was not
recognized until two days later.
In the event of a LOCA combined with a single failure of isolation
valve FCV 1112 (isolates the RCS loop "A" cold leg, and auxiliary
spray/hot leg recirculation paths) during the 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> CV-304 was
inoperable, inadequate core cooling would have occurred.
Failure of the valve to close was attributed to failure of an
Automatic Switch Co three-way solenoid air valve. The manufacturirg
process utilized Dow Corning 550 lubricant, which hardened with
elevated tempEratures. The valve was replaced. (Event date:
8/23/89).
2. Preliminary Nctifications
Eight preliminary notifications (PNs) pertaining to Unit 1 were issued by
Region V during the assessment period. For those events described in the PIs
which warranted LERs from the licensee, the LERs were verified to have been
submitted. No omissions were identified.
S. LER Overview
Causes of the events are distributed among various categories, however an
inordinate number of the LERs were associated with design and design change
programmatic deficiencies.
4. LER Timeliness and Quality
LERs submitted by the licensee were timely and of high quality, with the
exception of LER 89-11. LER 89-11 indicated a supplemental LER was expected
to be issued by June 16, 1989, however, it was not issued until December 5,
1989.
5. 10 CFR 50.72 Reports
Based upon preliminary information provided by the licensee in immediate
notification reports submitted pursuant to 1OCFR50.72, it appears additional
LERs should have been submitted to the NRC in accordance with 1OCFR50.73 on
the following events:
EN 14598:
Postulated overload of 480 volt switchgear 1 & 2 main feeder breaker
following initiation of safety injection without loss of offsite
power (Event Date:
1/30/89).
EN 15046:
Automatic start of an emergency diesel generator when restoring the
south circulating water pump to service (event date 3/17/89).
Region V should assess the need for additional 50.73 reports on these items.
6. Abnormal Occurrences and Other Events of Interest
No events occurring during this assessment period were classified as Abnormal
Occurrences for inclusion in the NUREG-0090 report to Congress.
7. AEOD Reports
No AEOD reports were issued regarding events occurring at San Onofre Unit 1
during this evaluation period.
ENCLOSURE
AEOD Input To SALP Review For San Onofre 2 & 3
The Southern California Edison Company submitted licensee event reports for
San Onofre Units 2 and 3 durine the assessment period from October 1, 1988 to
January 31, 1990. The reports for Unit 2 included LER numbers 361-88-028
through 361-88-037 and 361-89-001 through 361-89-011. The reports for Unit 3
included LER numbers 362-88-010 through 361-88-01? and 361-89-001 through
361-89-011. We reviewed those LERs and related event reports and our review
findings are as follows:
1. Significant Operdting Events
Based on the AEOD LER screening criteria, two of the unit 2 events during this
period were found to be important from the safety standpoint. The events are
as follows:
LER 361-88-034. On December 15, 1988, while operating at 100% power, it was
determined that the unit 2 component cooling water system (CCWS) did not meet
its design basis.
Specifically, safety related systems should be designed to
withstand the effects of natural phenomena such as earthquakes. However,
components in the component cooling water system were powered by non-1E, non
seismfic power supplies.
LER 361-89-004.
Or Feburary 9, 1989, unit 2 was taken critical with all four
channels of the Core Protection Calculators (CPCs) inoperable. This was the
result of a misunderstanding by the operators of the function of the CPC alarm
and annunciator lights.
None of the events at San Oriofre during this time period was determined to be
an abnormal occurrence.
2. Emergency Notification Reports
The 50.72 reports for this period were evaluated and compared to the LERs
submitted. It was found that LERs had been submitted where appropriate for
events described in 50.72 reports for San Onofre units 2 and 3.
3. AEOD Technical Study Reports
None of the events at San Onofre during the time period of this assessment
was the subject of an in-depth technical study by AEOD.
4. Preliminary Notifications of Event or Occurrence
Six PNOs were issued during the period of the assessment. They are as
follows:
.
PNO-V-88-062; on 881119, an earthquake occurred 30 miles west of San Clemente.
PNO-V-89-004; cn 890106, a reactor trip and safety injection actuation
occurred at Unit 3. It was caused by failure of a non-1E power supply due to
a ground jumper. The jumper was removed and steam generator level sensing
lines blown down for sludge accumulation. (This was later reported in LER
362-89-001.
PNO-V-89-006; on 890111, a plant shutdown of Unit 2 was required by technical
specifications due to an inoperable motor-driven auxiliary feedwater pump.
(This was later reported in LER 361-89-001.)
PNO-V-89-008; On 890118, a magnitude 5 earthquake occurred 8 miles south of
MalibL.
PNO-V-89-014; on 890209, panel annunciators illuminated before the Unit 2
startup which indicated the core protection calculators were inoperable, but
the crew observed that the console indications were normal.
(This was later
reported in LER 361-89-004.)
PNO-V-89-023; on 890407, a magnitude 4.6 earthquake occurred near Newport
Beach. Unit 1 reported no damage.
PNO-V-89-025; on 890407, Unit 3 went into an unscheduled shutdown for more
than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. This was caused by a reactor trip due to a drop in voltage on
the rod drive bus after a breaker trip, an atmospheric dump valve not
operating properly, and a leak in the vent line.
(This was later reported in
LER 362-89-006.)
PNO-V-89-028; on 890512, a primary-to-secondary leak rate of 117 gallons per
day occurred at Unit 3. On 890513, steam generator blowdown radiation monitor
indication increased one decade.
The reactor was to be shutdown and drained
to mid-loop tc repair the leaking tube(s).
PNO-V-89-038; on 890629, excessive shaft leakage was identified while
performing inservice testing of a LPSI pump at Unit 3. (This was reported in
LER 362-89-008.)
PNO-V-89-068; on 891201, a hydrogen fire in the radwaste building occurred
during changeout of a relief valve on a waste gas decay tank. There were
no injuries, no equipment damage, and no release of radioactive material.
It appears that LERs have been submitted where required for events described
by the Region in PNOs.
5. LER Quality
The LERs described the major aspects of the events, including component or
system failures that were contrituting factors.